Methods and systems for monitoring well integrity and increasing the lifetime of a well in a subterranean formation

ABSTRACT

A system for increasing the detecting degradation of a wellbore. The system comprises a computer memory configured for storing computing instructions and a processor operably coupled to the computer memory. The system comprises a sensor operably coupled to the computer memory and is configured to determine the presence of at least one chemical species indicative of degradation of the wellbore in a fluid exiting the wellbore. Methods of monitoring a wellbore for corrosion or other degradation of one or more components of wellbore equipment are disclosed as are methods of increasing the lifetime of a wellbore.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional PatentApplication Ser. No. 61/927,735, filed Jan. 15, 2014, and entitled“METHODS AND SYSTEMS FOR MONITORING WELL INTEGRITY IN A SUBTERRANEANFORMATION,” the disclosure of which application is hereby incorporatedherein in its entirety by reference.

FIELD

Embodiments of the disclosure relate generally to methods and systemsfor monitoring a downhole environment for corrosion and degradation ofdownhole equipment and components during downhole operation such asdrilling of a wellbore, formation stimulation, and production.

BACKGROUND

During the lifetime of a well, the equipment used to construct andproduce from the well may interact with different types of fluids, suchas drilling fluids, stimulation fluids, completion fluids, formationfluids, fluids injected into an adjacent well, etc. Depending on theirchemical properties, these fluids, which may be characterized generallyas “corrosive fluids,” may react with some of the materials within thewell and with each other, causing corrosion, scaling and/or otherdegradation of the equipment within the well. Casing, liner, and cementlining the annulus between casing or liner and the wellbore wall areconventionally employed to enhance the stability of the well duringdrilling operations and/or production operations.

During the drilling of a wellbore, the drilling fluid contacts materialswithin the borehole such as drilling equipment, and any constructionmaterial such as casing and liner strings which may be in place withinthe wellbore. The drilling fluid may also interact with the formationand the formation fluid. The drilling fluid may invade into theformation and remain in reservoir and non-reservoir sections of theformation, or may later be removed with formation fluids duringproduction. During a later stimulation stage, the stimulation fluid maybe in contact with casing and liner strings, stimulation equipment, anyother equipment in the borehole, the formation, and formation fluids.The stimulation fluids may remain in the formation until at least aportion of the stimulation fluid is removed with the formation fluidduring production. Fluids may be injected into the well or into anadjacent well and may pass through the formation and be produced at aproduction well. During the production stage, completion fluid, residualdrilling fluid, residual stimulation fluid remaining in the formation,and injected fluids may interact with each other, and with exposedsurfaces of the casing, liners, tubing, the formation, and the formationfluid. The formation fluid may interact with exposed surfaces of thecasing, liners, tubing, and the formation as it travels to the surface.Although the downhole equipment may be in contact with such fluids foronly short periods of time, such as during drilling or stimulation,considerable degradation of equipment may take place due to the contactand interaction with the fluids.

After construction of the well, the formation fluid, produced fluid,residual drilling fluid, and residual stimulation fluid may be incontact with the casing, liner, and other components for longer periodsof time. Although production wells may be equipped with corrosionresistant materials, with time, and particularly when aggressive fluidsare produced, the integrity of these materials and materials withlimited corrosion resistance may be reduced, which may enable thecorrosive fluids to contact the casing, liner, tubing or other wellconstruction equipment.

In addition, exposing cement within a well to formation fluids, drillingfluids, completion fluids, injected fluids, stimulation fluids, andmixtures thereof may cause the cement to degrade and crack. As thecement cracks, outer surfaces of the metal casing contacting andsupported by the cement may become exposed to produced fluids, formationfluids, drilling fluids, completion fluids, injected fluids, stimulationfluids, and mixtures thereof. The metal and cement may react with suchfluids.

BRIEF SUMMARY

Embodiments disclosed herein include systems for monitoring theintegrity of a well and methods of reducing degradation of at least onewellbore component. For example, in accordance with one embodiment, amethod of monitoring degradation of a wellbore comprises predicting atleast one reaction between at least one of a formation fluid, a drillingfluid, a stimulation fluid, a completion fluid, an injected fluid, acomponent of wellbore equipment, a formation, and another of theformation fluid, the drilling fluid, the stimulation fluid, thecompletion fluid, the injected fluid, the component of wellboreequipment, and the formation using at least one of thermodynamicequations and chemical reaction kinetics equations, identifying at leastone property of a fluid exiting the wellbore, wherein the at least oneproperty is indicative of the at least one reaction, and analyzing thefluid exiting the wellbore for changes in the at least one property.

In additional embodiments, a method of reducing degradation of awellbore comprises determining a composition of at least one of aformation and a formation fluid within a wellbore, predicting at leastone reaction between the formation fluid and at least one of wellboreequipment, the formation, a drilling fluid, a stimulation fluid, aninjected fluid, and a completion fluid, identifying at least onechemical species in the fluid exiting the wellbore, wherein the at leastone chemical species is indicative of the at least one predictedreaction, and adjusting a composition of the injected fluid into thewellbore responsive to detection of the at least one chemical speciesindicative of the at least one predicted reaction in the fluid exitingthe wellbore.

In further embodiments, a system for detecting degradation of wellboreequipment within a wellbore comprises a computing system comprising acomputer memory configured for storing computing instructions and aprocessor operably coupled to the computer memory and configured forretrieving the computing instructions from the computing memory andexecuting the computing instructions to predict a composition of asubsurface formation fluid and at least one reaction between thesubsurface formation fluid and at least one of a drilling fluid, astimulation fluid, a completion fluid, an injected fluid, and at leastone component of wellbore equipment. The system further comprises asensor operably coupled to the computing system, the sensor located andconfigured to detect at least one property of a produced fluid, whereinthe at least one property is indicative of the at least one reaction.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a simplified block diagram of a computing system configuredfor carrying out one or more embodiments of the present disclosure;

FIG. 2 is a cross-sectional side view of a well during a drillingprocess;

FIG. 3 is a cross-sectional side view of a well during a drillingprocess and showing possible interactions between fluid, technicalequipment, and the formation;

FIG. 4 is a simplified flow diagram for monitoring of a wellbore duringthe drilling process according to embodiments of the disclosure;

FIG. 5 is a cross-sectional side view showing an intact borehole anddifferences in the produced fluid due to a decrease in temperature andpressure as the production fluid is brought to the surface;

FIG. 6 is a cross-sectional side view showing possible reactions thatmay take place between fluid and the well as the fluid is brought to thesurface in a production process;

FIG. 7 is a cross-sectional side view showing a production well and anearby injection well; and

FIG. 8 is a simplified flow diagram showing a process of monitoring thestatus of the wellbore according to other embodiments of the disclosure.

DETAILED DESCRIPTION

The illustrations presented herein are not meant to be actual views ofany particular material, apparatus, system, or method, but are merelyidealized representations that are employed to describe certainembodiments of the present invention. For clarity in description,various features and elements common among the embodiments of theinvention may be referenced with the same or similar reference numerals.

Those of ordinary skill would appreciate that the various illustrativelogical blocks, modules, circuits, and algorithm acts described inconnection with embodiments disclosed herein may be implemented aselectronic hardware, computer software, or combinations of both. Toclearly illustrate this interchangeability of hardware and software,various illustrative components, blocks, modules, circuits, and acts aredescribed generally in terms of their functionality. Whether suchfunctionality is implemented as hardware or software depends upon theparticular application and design constraints imposed on the overallsystem. Skilled artisans may implement the described functionality invarying ways for each particular application, but such implementationdecisions should not be interpreted as causing a departure from thescope of the embodiments described herein.

In addition, it is noted that the embodiments may be described in termsof a process that is depicted as a flowchart, a flow diagram, astructure diagram, or a block diagram. Although a flowchart may describeoperational acts as a sequential process, many of these acts can beperformed in another sequence, in parallel, or substantiallyconcurrently. In addition, the order of the acts may be re-arranged. Aprocess may correspond to a method, a function, a procedure, asubroutine, a subprogram, etc. Furthermore, the methods disclosed hereinmay be implemented in hardware, software, or both. If implemented insoftware, the functions may be stored or transmitted as one or moreinstructions or code on a computer-readable medium. Computer-readablemedia includes both computer storage media and communication mediaincluding any medium that facilitates transfer of a computer programfrom one place to another.

Information and signals described herein may be represented using any ofa variety of different technologies and techniques. For example, data,instructions, commands, information, signals, bits, symbols, and chipsthat may be referenced throughout the description may be represented byvoltages, currents, electromagnetic waves, magnetic fields or particles,optical fields or particles, or combinations thereof. Some drawings mayillustrate signals as a single signal for clarity of presentation anddescription. It should be understood by a person of ordinary skill inthe art that the signal may represent a bus of signals, wherein the busmay have a variety of bit widths and the present disclosure may beimplemented on any number of data signals including a single datasignal.

According to embodiments disclosed herein, the conditions within a wellmay be monitored to determine the integrity of the well during the lifeof the well. Monitoring of the well may include monitoring the chemicalproperties and/or physical properties, such as pH, redox potential,chemical composition (including gases that may be present in a fluidsample), viscosity, electrical conductivity (or the electricalresistivity), and salinity and density of a fluid such as a drillingfluid, formation fluid, completion fluid, stimulation fluid, injectedfluid, produced fluid, and mixtures thereof, during normal operations,including during drilling, production, well testing, and wellremediation. Monitoring of the chemical and physical properties of afluid exiting the well may enable the detection of possible interactions(e.g., corrosion, degradation, etc.) between the fluids within the welland technical components and downhole equipment (e.g., drillingequipment, casing, liner, tubing, packers, etc.) within the wellbore, aswell as interactions with cement employed to line the wellbore and theformation.

As used herein, the term “produced fluid” means and includes the fluidproduced by the well at the surface of the well, mostly including theformation fluid (such as, hydrocarbons, water, or emulsions ofhydrocarbons and water), but which can be mixed and interact withresidual drilling fluid, stimulation fluid, completion fluid or injectedfluids. The term “wellbore equipment” as used herein means andencompasses equipment and material components disposed in a wellboreduring drilling, completion, injection, and production (includingstimulation and other remedial actions within the wellbore). Forexample, wellbore equipment includes casing strings, liner strings,tubing, cement, drilling equipment, and sealing equipment such aspackers and elastomers. The integrity of the wellbore equipment withinthe well may be monitored using modeling methods described herein incombination with regular or occasional sampling of fluids. Based on theresults of sampling compared to predicted modeling results, theoperation of the wellbore may be altered to maintain the integrity ofthe well.

Embodiments of the disclosure include systems and related methods fordetermining the occurrence of degradation within a wellbore duringdrilling, completion, injection, stimulation, and production. As usedherein, the term “degradation” means and includes any form of damage,including corrosion, erosion, cracking, and the combination of thesemechanisms etc. Furthermore, degradation of a wellbore may include aninflux of formation fluid into the well during drilling (what is knownin the art as a “kick”). Degradation also includes the release of toxicor corrosive gases from the formation that may damage materials withinthe well.

FIG. 1 is a simplified block diagram of a computing system 100configured for carrying out one or more embodiments of the presentdisclosure. The computing system 100 is configured for executingsoftware programs containing computing instructions and may include oneor more processors 110, one or more memory 120 devices, one or moreoperational storage 130 devices, one or more communication elements 150,and one or more user interface 140 devices.

The one or more processors 110 may be configured for executing a widevariety of operating systems and applications including the computinginstructions for carrying out embodiments of the present disclosure.

The memory 120 may be used to hold computing instructions, data, andother information for performing a wide variety of tasks includingperforming embodiments of the present disclosure. By way of example, andnot limitation, the memory 120 may include Synchronous Random AccessMemory (SRAM), Dynamic RAM (DRAM), Read-Only Memory (ROM), Flash memory,phase change memory, and other suitable information storage devices. Thememory 120 may include data related to the formation, including thechemical composition of the formation, as well as the mineralogical dataabout the formation. As used herein, the composition of a material meansand includes a concentration of at least one chemical species (e.g.,element, ion, molecule, compound, substance, etc.) in the material. Asused herein, if not specified, the composition of the formation refersto one or both of the chemical composition and the mineralogicalcomposition of the formation. The formation may also refer to fluidspresent within the formation (i.e., formation fluids) and thecomposition of the formation may also refer to the composition of suchformation fluids. The formation may also refer to any formation fluidspresent within the formation. The memory 120 may include data relatingto wellbore equipment such as chemical composition of materials used forcasing strings, liner strings, drill strings, production strings, andcement within the well. The memory 120 may also include data relating toother well-related variables such as chemical composition and pH of theformation fluid (e.g., formation water, gases, and other hydrocarbonswithin the formation, etc.), information such as the chemicalcomposition of drilling fluid into and out of the well, informationabout the chemical composition of a produced fluid leaving the well,information about the chemical composition of the stimulation fluid andthe chemical composition of a completion fluid. The memory 120 mayinclude historical information, such as historic drilling fluid chemicalcomposition into and out of the well and historical chemical compositiondata of produced fluids leaving the well. The memory 120 may alsoinclude information about the physical properties of such fluids, suchas information about the density, viscosity, and electrical conductivityof the fluids. The fluid leaving the well may be monitored for changesin physical or chemical properties such as changes in the concentrationof particular chemical species, or changes in at least one of density,viscosity, electrical conductivity, salinity, redox potential, and pH ofsuch fluids. The memory 120 may also include information abouttemperatures and pressures at various depths and locations within theformation and the wellbore.

The communication elements 150 may be configured for communicating withother devices or communication networks. By way of example, and notlimitation, the communication elements 150 may include elements forcommunicating on wired and wireless communication media, such as, forexample, serial ports, parallel ports, Ethernet connections, universalserial bus (USB) connections IEEE 1394 (“firewire”) connections,bluetooth wireless connections, 802.1 a/b/g/n type wireless connections,cellular phone wireless connections and other suitable communicationinterfaces and protocols. Typically, communication between downholeequipment and surface can be performed via mud-pulse telemetry,wired-pipe technology, transmission via electromagnetic or acousticfields, wireline, fiber optic wireline, and other devices.

The operational storage 130 may be used for storing information innon-volatile memory for use in the computing system 100. The operationalstorage 130 may be configured as one or more storage devices. By way ofexample, and not limitation, these storage devices may includecomputer-readable media (CRM). This CRM may include, but is not limitedto, magnetic, optical, and solid state storage devices such as diskdrives, magnetic tapes, CDs (compact discs), DVDs (digital versatilediscs or digital video discs), FLASH memory, and other suitableinformation storage devices.

The user interface 140 may include input devices and output devicesoperably coupled to the processor 110. By way of non-limiting example,the input devices may include elements such as a keyboard, a numericalkeypad, a mouse, a touchscreen, a button array, a track pad, a remotecontrol, cameras, sensors, a microphone, and combinations thereof. Theinput devices may be configured to receive commands from the user andpresent the commands to the processor 110 to perform operationsresponsive to the commands. The input devices may include sensors,cameras, or combinations thereof configured to capture the signals usedin the analysis discussed herein. In some embodiments, the input devicesinclude temperature sensors, pressure sensors, sensors for assessing thedensity, viscosity, electrical conductivity, and pH of a fluid, andsensors for measuring the chemical composition of a fluid in real-time.In other embodiments a pH, density, viscosity, electrical conductivity,and the concentration of chemical species of a fluid may be measured ina laboratory and input into the user interface 140 through an inputdevice. Such information may be stored in the memory 120. In someembodiments, a portion of the input devices (e.g., including sensors,camera, or combinations thereof) may not be a part of the user interface140.

By way of non-limiting example, the output devices may include one ormore displays such as a light-emitting diode (LED) array, a segmenteddisplay, a liquid crystal display, a cathode ray tube display, a plasmadisplay, and other types of electronic displays. The output devices mayalso include other peripheral output devices, such as speakers. In someembodiments, the input devices and the output devices may be integratedin or controlled by the same device, such as, for example, a touchscreendisplay. In other embodiments, the input devices and the output devicesmay be implemented in separate devices, such as a keyboard and an LCDmonitor, respectively. In some embodiments, the output device maydisplay one or more recommended actions determined by the computingsystem 100 for reducing degradation of a well.

Software processes illustrated herein are intended to illustraterepresentative processes that may be performed at least partly by one ormore computing systems 100 in carrying out embodiments of the presentdisclosure. Unless specified otherwise, the order in which the processesare described is not to be construed as a limitation. By way of exampleonly, software processes may be stored on one or more operationalstorage 130 devices, transferred to a memory 120 for execution, andexecuted by one or more processors 110. Some or all of the softwareprogram may be stored and executed remotely and accessed (e.g., as a webinterface). Also, some or all of the software program may be stored andexecuted as a standalone application on a computer, or a personalcommunication device such as a tablet computer or a cellular telephone.

When executed as firmware or software, the instructions for performingthe processes may be stored or transferred on a computer-readablemedium. In addition, when executing firmware or software instructions,the computing system 100 should be considered a special purposecomputing system and the processor 110 may be considered a specialpurpose processor configured for carrying out embodiments of the presentdisclosure.

Other combinations or separations of the elements of the computingsystem 100 are possible, and those of ordinary skill in the art willappreciate that signals may be communicated between the various elementsof the computing system 100 in various ways. By way of non-limitingexample, the user interface 140 may be implemented remote from theoperational storage 130 as a portable communication device, such as atablet computer or a remote control. The user interface 140 may beconfigured to send and receive signals to the processor 110 through anyof the communication elements(s) 150, a mobile data network, infrared,Bluetooth, a wireless network, a cable, and combinations thereof.

The processor 110 may be configured to control the computing system 100.The processor 110 may be operably coupled to the memory 120, theoperational storage 130, the user interface 140, and the communicationelement 150. The processor 110 may be configured to receive informationfrom the user interface 140 (e.g., such as from an input device) and thememory 120 and process the data to determine one or more conditionswithin the well. The processor 110 may predict a current condition ofthe well by satisfying thermodynamic equations, chemical kineticsequations, geochemical equations, and combinations thereof. Thethermodynamic equations, chemical kinetics equations, and geochemicalequations may receive inputs from the memory 120 and the user interface140. The processor 110 may determine one or more conditions within thewell, such as one or more reactions that may take place within the well,one or more reaction byproducts, a composition of one or more fluids, ora condition (e.g., pH, density, viscosity, temperature, resistivity,redox potential, salinity, chemical composition, etc.) of one or morefluids.

The one or more reactions within the well may include a reaction betweenat least one of a drilling fluid, a completion fluid, a stimulationfluid, an injected fluid, a formation fluid, a produced fluid, theformation, and the wellbore equipment with at least another of thedrilling fluid, the completion fluid, the stimulation fluid, theinjected fluid, the formation fluid, the produced fluid, the formation,and the wellbore equipment. The one or more reactions may include one ormore of a corrosion reaction and any other type of degradation reactionof wellbore equipment. In some embodiments, where the processor 110predicts or detects one or more significant reactions that may takeplace within the well (e.g., degradation, corrosion, etc.), theprocessor 110 may recalculate (e.g., predict) one or more reactions thatmay take place within the well and determine one or more reactionbyproducts, changes in composition of a fluid exiting the well, orchanges in a condition of a fluid exiting the well based on an alteredchemical composition of fluid being pumped into the well (e.g., thedrilling fluid, stimulation fluid, completion fluid, injected fluid, acorrosion inhibitor, scavengers, biocides, and mixtures thereof, etc.).The processor 110 may predict or detect the one or more reactions thatmay take place within the well prior to operation of the wellbore orduring operation of the wellbore. The processor 110 may send anelectronic signal to the user interface 140 or to a chemical injectionpump to alter a concentration of a chemical species of a fluid beingpumped into the well. For example, the processor 110 may recommendchanging the composition of a fluid being pumped into the well to reducedegradation of the well. The recommendation may be transferred to a uservia the output device of the user interface 140. The processor 110 mayalso determine an optimal altered composition by iteratively altering acomposition of the fluid to be pumped downhole. The altered compositionmay be based on predictions made by the processor 110 about reactions ofthe altered fluid composition below the surface of the formation. Thecomposition alteration may take place until the processor 110 predictsthat the fluid being pumped into the well does not cause substantialdegradation of the well and/or wellbore equipment.

The processor 110 may determine one or more conditions that arecharacteristic of the one or more predicted reactions within the well.The one or more conditions may include characteristic properties (e.g.,marker materials) that include a change in a concentration of aparticular chemical species (e.g., an ion, element, compound, molecule,substance, material, etc.) in a fluid exiting the well or a change in aproperty, such as density, viscosity, electrical conductivity, redoxpotential, salinity, or pH, of the fluid exiting the well. Eachcharacteristic property or combination of characteristic properties maybe specific to a type of reaction taking place within the well. Forexample, the presence of particular chemical species, ions, elements,compounds, or molecules in a fluid leaving the wellbore may be an earlyindication of integrity degradation of wellbore equipment (such ascorrosion), an indication that the formation pressure is higher than thewell pressure and formation fluid is entering the well, or an indicationthat cement within the well is damaged.

The processor 110 may compare a predicted composition or condition of afluid exiting the well to the current composition or condition of afluid exiting the well. The processor 110 may indicate when the currentcondition of the well is different from that predicted by the processor110. For example, a fluid exiting the well may be analyzed andinformation (e.g., composition, pH, density, viscosity, conductivity,etc.) about the fluid exiting the well may be stored in the memory 120.The processor 110 may compare the information in the memory 120 to thepredicted conditions of the fluid exiting the well. Where a condition ofthe fluid exiting the well is substantially different than predicted bythe processor 110, the processor 110 may suggest, initiate, or controlaltering a composition of a fluid being pumped into the well. Forexample, the processor 110 may send an electronic signal to an outputdevice of the user interface 140 directing an operator to adjust acomposition of a fluid (e.g., a drilling fluid) into the well. Inanother embodiment, the processor 140 may send an electronic signal tothe communication element 150 to send a signal to a chemical injectionpump to alter an injection rate of a particular material into the well.

The composition of the produced fluid at the surface of the wellbore maybe predicted by software of the computing system 100 including programs,modules, and algorithms for identifying and simulating chemicalreactions that may take place between the drilling fluid, stimulationfluid, formation fluids, the formation, and wellbore equipment using oneor more of thermodynamic-based, reaction kinetics-based, andgeochemical-based algorithms to predict reactions that may take placewithin a wellbore system. The software of the computing system 100 mayalso include programs, modules, and algorithms for identifying andsimulating physical and chemical processes that take place as the fluidstravel from high temperature and high pressure environments below theearth's surface to lower pressures and temperatures as they travelthrough the wellbore to the earth's surface. For example, formationfluid may change as it comes to the surface due to changes of physicalparameters, (e.g., temperature and pressure between subsurface andsurface). The software may also compare data produced by analyzingsamples of the fluid leaving the well with the predicted composition andproperties of the fluid leaving the well based on geochemical modelingand historical data regarding chemical and physical properties such aspH, chemical composition, density, viscosity, electrical conductivity,redox potential, salinity, etc., of the produced fluid.

The software for modeling chemical reactions within the well may be freeor commercially available software, such as PHREEQC, available from theUnited States Geological Survey (USGS), TOUGHREACT, available from theLawrence Berkeley National Laboratory, or Aspen Plus®, available fromAspen Technology, Inc., of Burlington Mass., for modeling thermodynamicand kinetic modeling of reactions. Software for modeling corrosion mayinclude NORSOK M-503 according to the Norwegian standard M-503,Cassandra corrosion model from BP of London, England, de Waard fromShell International, Multicorp available from the Ohio University,Predict from Honeywell Process Solutions, of Honeywell of Morristown,N.J., or other corrosion models. In one aspect, the software may be usedby the one or more processors 110 to analyze some or all of theinformation in the memory 120 to estimate or predict one or moreparameters of well operation. Inputs into the software program mayinclude information stored in memory 120 such as one or more of thetemperature and pressure within the formation, thermodynamic equations,reaction kinetic equations, information about the composition ofequipment and components within the wellbore, the composition of theformation, the composition of formation fluid, the composition ofstimulation fluid, the composition of drilling fluid, the composition ofthe completion fluid, and the composition of the injected fluid. Thethermodynamic equations and reaction kinetic equations may utilize theinputs (e.g., temperature, pressure, composition of the formation andvarious fluids) to predict chemical reactions that may take place withinthe wellbore.

FIG. 2 illustrates a downhole system 200 during a drilling process. Adrill string 210 may be connected to a motor or rotation inducingelement to form a wellbore in a subterranean formation 205. A cuttingelement 215 such as a drill bit, a reamer, etc., may be at a distal endof the drill string 210. A metal casing 220 may line the borehole formedin the subterranean formation 205. Cement 230 may be formed between themetal casing 220 and the subterranean formation 205. Sections of thewellbore where the drill string 210 is not surrounded by a metal casing220 or cement 230 may be referred to as an open hole 240. The downholesystem 200 may include additional casing strings, including intermediatecasing (not shown). Drilling fluid may pass through the downhole system200 through an inlet 250 and exit at an outlet 260.

Referring to FIG. 3, a downhole system 200 is shown including thevarious ways a drilling fluid may interact with the downhole system 200.FIG. 3 illustrates various reactions that may take place between thedrilling fluid and the downhole system 200. For example, the drillingfluid may react with formation fluid in the borehole or in the vicinityof the borehole in reaction 252 along the open hole 240 sections of thewellbore, the drilling fluid may react with the formation in reaction254, the drilling fluid may react with materials of the variouscomponents of the drill string 210 in reaction 256, the drilling fluidmay react with the metal casing 220 in reaction 258, and the drillingfluid may react with cement 230 in reaction 259.

Referring to FIG. 4, with continued reference to FIG. 1 through FIG. 3,a method 400 of monitoring, and potentially reducing, integritydegradation of one or more components of a downhole system (e.g., acomponent of a drilling system or a component of a partially completedwell) during a well operation is shown. The method 400 includes act 402of determining a chemical composition of a formation and the formationfluid. Information for characterizing the composition of each of theformation and the formation fluid, may be obtained from samples obtainedfrom a well proximate the downhole system to be monitored, or from thewellbore being drilled. For example, at least a portion of theinformation may be obtained from samples of the formation core or fluidsamples in the same well or from an adjacent well. The samples of theformation and the formation fluid may be obtained subsurface (e.g.,coring) or at the surface (e.g., cuttings). The samples may be analyzedsubsurface or may be brought to the surface and analyzed at the surface.The core samples and the fluid samples may be analyzed downhole andanalysis transmitted in-situ or the samples may be stored in a downholetool, brought to the surface, and retrieved from the tool at the surfacefor further analysis. In some embodiments, a starting composition of thefluid is determined by assuming that the formation fluid includes purewater or an assumed hydrocarbon composition (e.g., based on known welldate of adjacent wells). In some embodiments, properties of theformation and the formation fluid, such as the composition of theformation, the type of formation fluid (e.g., water, hydrocarbon, ormixture thereof), and salinity of the formation fluid may be determinedfrom downhole logging. Logging may include resistivity logging, porositylogging, spectral gamma ray logging, mineralogical logging, or otherlogging technique employed throughout the industry. In some embodiments,resistivity logging may be used to determine a property indicative ofthe composition of the formation fluid, such as the salinity of theformation fluid.

Act 404 may include predicting a composition of the formation fluidbased on the assumed starting composition of the formation fluid, thecomposition of the formation, and the temperature and pressure withinthe formation. The assumed starting composition of the formation fluidmay be pure water. In other embodiments, the assumed startingcomposition of the formation fluid may be an assumed hydrocarboncomposition, based on known well and formation data of wells proximatethe wellbore. The composition of the formation fluid may be estimatedbased on the assumed starting composition and predicted ways the assumedcomposition of formation fluid interacts with the formation attemperatures and pressures within the well. In one embodiment, thesoftware may predict the composition of the formation fluid based onpredicted interactions between the formation and pure water usinginformation about the chemical composition and the mineralogicalcomposition of the formation.

In some embodiments, the composition of the formation fluid may becalibrated. The software may predict the composition of the formationfluid as it passes from high temperatures and pressures within theformation to the surface and may predict the composition of theformation fluid at the surface. For example, solids may precipitate orgases may degas out of the formation fluid as the formation fluid passesfrom high temperature and high pressure subsurface to the surface. Thepredicted composition of the formation fluid may be compared to thecomposition of an actual sample of the formation fluid obtained tocalibrate the model. For example, where the composition of the formationfluid at the surface predicted by the processor 110 does not match theactual composition of the fluid exiting the well, the inputs to thesoftware may be adjusted (i.e., calibrated) until the composition of theformation fluid at the surface matches the actual composition of theformation fluid at the surface. At least one of the thermodynamic andchemical reaction kinetic inputs and the temperature and pressure withinthe well may be altered until the predicted composition of the fluidexiting the well matches the actual composition of the fluid exiting thewell. For example, a predicted temperature or a predicted pressure maybe altered until the predicted composition of the fluid exiting thewellbore matches the actual composition of the fluid exiting thewellbore. When the predicted composition of the formation fluid at thesurface matches the actual composition of a sample of the formationfluid at the surface, the composition of the formation fluid subsurfacemay be validated. Thus, the modeled formation fluid within the wellboremay become a reference fluid for modeling processes that occursubsurface.

In other embodiments, the composition of the formation fluid subsurfaceis determined based on the composition of a sample of the formationfluid at the surface and predicted (e.g., modeled) changes incomposition of the formation fluid as the formation fluid travels fromhigh temperature and high pressure subsurface to atmospheric temperatureand pressure at the surface. For example, the composition of theformation fluid may alter as it travels from below the surface to thesurface because of changes in temperature and pressure as the formationfluid travels towards the surface. In some embodiments, the softwareprogram may interact with the one or more processors 110, the userinterface 140, the operational storage 130, the memory 120, and thecommunication elements 150 to predict a composition of the formationfluid at a surface of the wellbore.

Act 406 includes predicting possible chemical reactions (e.g., reactions252, 254, 256, 258, and 259) that may take place in the well. Thechemical reactions may be predicted by the computing system 100 and theprocessor 110 as described above. Potential reactions include reactionsbetween the drilling fluid, and at least one of the formation fluid(e.g., using the predicted composition of the formation fluid within thewell), the formation, and the well equipment (e.g., drill string, casingstring, coiled tubing, production tubing, downhole pumps, valves,sensors, etc.), or other wellbore equipment. The computing system 100may consider the effects of changes in temperature and pressure asfluids travel from below the surface to the surface. In someembodiments, the computing system 100 accounts for degassing orprecipitation of solids as fluids travel from higher temperatures andhigher pressures below the surface to surface temperatures and pressures(e.g., ambient temperature and pressure).

By way of non-limiting example, reaction 252 between the drilling fluidand the formation fluid may include mixing of the formation water withthe drilling fluid, such as where a pressure of the formation fluid ishigher than a pressure of the drilling fluid and the formation waterflows into the well and mixes with the drilling fluid (i.e., a “kick”).For example, severe kicks may be related to the volume expansion ofgases as they are brought from high pressures within the formation toatmospheric pressure at the surface. In some embodiments, the amount offormation fluid entering the wellbore may be predicted by estimating(e.g., with the computing system 100) the volume of gas that may bereleased per unit volume of formation fluid transported from subsurfaceto the surface. The actual volume of gases exiting the borehole may becompared to the predicted volume of gases that would exit the boreholeper unit volume of formation fluid.

In some embodiments, the computing system 100 may predict how thedrilling fluid may interact with the formation, the formation fluid, orthe well equipment in one or more reactions. For example, reaction 254(FIG. 3) may include a reaction of the drilling fluid with the formationfluid. In some embodiments, the drilling fluid may interact with acidgases such as CO₂, H₂S, or other materials present within the formation.In other embodiments, chloride ions may be dissolved into the drillingfluid. The CO₂, H₂S, or chloride ions may dissolve in the drilling fluidand cause further reactions with the drilling fluid. For example, theacid gases may consume acid gas scavengers, or may reduce theconcentration of bases such as magnesium oxide or other additives in thedrilling fluid or mud, or may alter physical properties of the drillingfluid by degrading viscosifiers present in the drilling fluid. Reaction256 may include a reaction between the drilling fluid and the drillstring 210. For example, materials such as H₂S or CO₂ may corrode ordegrade construction material such as metallic materials, compositematerials, hard metals such as cemented carbide, elastomers, sealingmaterials, polytetrafluoroethylene (PTFE), polyetheretherketone (PEEK),and cement in the well. The presence of particular organic molecules andfunctional groups found in elastomers, polymers, and sealing materialswithin a well may be an early indication of degradation of elastomers,polymers and sealing materials. The presence of metallic ions of metalsused as construction material in the drill string 210 (such as ions ofiron, nickel, chromium, cobalt, aluminum, manganese, titanium, copper,etc.) may be an early indication of corrosion of the drill string 210.Reaction 258 may include a reaction between the drilling fluid and themetal casing. Ions of one or more metals forming the metal casing in thedrilling fluid exiting the wellbore may be an indication of degradationof the metal casing. By way of non-limiting example, the presence ofmetallic ions such as ions of iron (e.g., Fe³⁺, Fe²⁺), ions of chromium(e.g., Cr³⁺), ions of titanium (Ti²⁺), and ions of nickel (e.g., Ni²⁺)may be an early indication of corrosion of the casing material. Reaction259 may include a reaction between the drilling fluid and the cement ofthe wellbore. A change in the pH of a fluid exiting the well, a decreasein the concentration of magnesium, or an increase in silicates may be anindication of degradation of cement within the wellbore.

Act 408 includes adjusting the composition of the drilling fluid basedon the reactions predicted in act 406. For example, the composition ofthe drilling fluid may be altered to improve (e.g., optimize) thecompatibility of the drilling fluid with the formation, the formationfluid, and equipment within the wellbore (e.g., lower the reactivitybetween the drilling fluid and the formation, formation fluid, wellequipment, and/or cement). If the computing system 100 predictsconsiderable interactions between the drilling fluid and at least one ofthe formation fluid, the formation, the wellbore equipment, and cement,the composition of the drilling fluid may be adjusted to reduce orminimize such reactions. After the drilling fluid composition isadjusted, act 406 may be repeated to predict the possible reactionsbetween the altered drilling fluid composition and the downhole system.In some embodiments, act 408 may be repeated for various drilling depthsbased of the composition of the formation fluid at various depths withinthe well. For example, in deep wells, changes in formation and formationfluid composition with depth may require changes in drilling fluidcomposition at different depths within the well. Thus, at least one ofacts 408, 406, 404, and 402 may be repeated at various depths within thesubterranean formation 205 to predict what types of reactions may occurat various depths.

In each of the potential reactions between the drilling fluid and thedownhole system 200, specific characteristics (e.g., reactionbyproducts, pH change in fluid at the surface, etc.) may be identifiedby the computing system 100 to predict when and where particularreactions are taking place within the well. Act 410 includes identifyingmarker materials (e.g., identifiers), that may be an indication of acondition within the well. Each of the reactions predicted by thecomputing system 100 in act 406 may result in one or more unique markermaterials, such as a particular compound, element, ion, change in pH,change in density, change in viscosity, etc., that may be indicative ofa particular reaction taking place within the well. The computing system100 may identify one or more unique marker materials of each of thereactions predicted and may output this information to a user interface140. By way of non-limiting example, where the formation water includeslithium or strontium, the presence of lithium or strontium in a drillingfluid sample may be an early indication that the formation water ismixing with the drilling fluid. As another non-limiting example,degradation of cement lining the wellbore may be detected by a decreasedconcentration of magnesium, and changes in pH, or combinations thereofin a fluid exiting the well. Iron corrosion may be detected by reducedsulfate concentrations, increased iron concentrations, changes of pH,and combinations thereof, of the fluid exiting a well. Metal corrosionmay also be indicated by ions of iron, chromium, nickel, and titanium inthe fluid exiting the well.

The drilling fluid may be continuously monitored for one or more markermaterials that are indicative of the conditions within the well (e.g.,degradation reactions such as corrosion reactions or other undesiredreactions). Additional marker materials can be intentionally included incomponents and coatings as indicators for integrity degradation toimprove the sensitivity of the system.

In some embodiments, at least a portion of the wellbore may be formedfrom a multi-layered tubular component or a multi-layer coating may beapplied on a component of particular interest. Each layer (e.g.,coating) may be configured to provide at least one marker material upondegradation. Act 410 may include identifying the chemical markers thatmay be formed when such multi-layered tubular components or coatingsdegrade. For example, a tubular component (e.g., a casing string, aproduction string, etc.) may include one or more distinct layers ofvarious materials. The multi-layered tubular component may include anexposed layer with a defined thickness and chemical composition, forinstance, a magnesium-rich layer, which will be contacted with thedrilling fluid, and at least a second layer under the first layer. Thesecond layer may be formed of a different composition than the firstlayer, such as from an aluminum-rich layer. Degradation of the firstlayer may form a first marker material. An increase in a concentrationof the first marker material (e.g., magnesium) in a fluid leaving thewell may indicate corrosion or degradation of the first layer. As thefirst layer corrodes or degrades, the second layer may be exposed.Degradation of the second layer may form a second marker material (e.g.,aluminum). An increase in a concentration of the second marker materialin the fluid leaving the well may indicate degradation of the secondlayer. In some embodiments, a third layer, a fourth layer, etc., may beformed under the second layer. Each layer may include a differentcomposition than surrounding layers. In some embodiments, a first layer,a third layer, a fifth layer, etc., are formed from a first compositionwhereas a second layer, a fourth layer, a sixth layer, etc., are formedform a second composition. The layer may be continuous or discontinuous.In some embodiments, the layer or coating includes one or more regions(e.g., pockets) filled with the marker material within the tubularcomponent. The pocket may be exposed and the marker material may bereleased after a predetermined amount of degradation of the tubularcomponent. The tubular component may include a plurality of pocketsincluding one or more marker materials configured to be released after apredetermined amount of degradation of the tubular component. For eachpredetermined amount of degradation of the tubular component, adifferent marker material may be released. The memory 120 may includeinformation (e.g., the location of, the amount and type or markermaterial, etc.) about each of the layers or regions of the multi-layeredtubular component.

Degradation of each of the layers may form a marker material that is nototherwise present in any of the formation fluid, drilling fluid, orstimulation fluid within the subterranean formation. Once the firstlayer begins to corrode, the first marker material may be detected inthe produced fluid. When the next layer of the wellbore constructionbegins to corrode, a concentration of the first marker material in afluid exiting the well may decrease and a concentration of the secondmarker material may increase in the fluid exiting the well. In thismanner, the corrosion of the overall wellbore construction may bemonitored.

In some embodiments, the wellbore construction may include varyingcompositions at various depths or wall thicknesses of the wellbore. Forexample, the wellbore construction may include materials or coatingssuch that marker materials are released after corrosion has reached acertain depth. The marker materials may be selected to be distinct fromthe composition of the drilling, stimulation, and formation fluids.These marker materials may be detected at a low concentration. In someembodiments, the marker materials include metal-binding dyes such asrhodamine B and fluorescein.

Act 412 includes obtaining samples of the drilling fluid and analyzingthe samples for the presence of one or more marker materials identifiedin act 410. Thus, the drilling fluid or fluid leaving the well may berepeatedly analyzed to determine the presence of the characteristicmarker materials identified in act 410. The composition and propertiessuch as pH, density, viscosity, conductivity, salinity, and redoxpotential of the drilling fluid may be stored in memory 120.

Act 414 includes monitoring the fluid obtained in act 412 for changes incomposition. In particular, a change in a concentration of a particularmarker material or group of marker materials may be identified bycomparing a current sample analysis to past sample analyses. In someembodiments, the computing system 100 compares a current sample of thedrilling fluid to historic data stored in the memory 120. Thus, thedrilling fluid may be monitored for changes in the concentration ofparticular elements, ions, compounds, chemical species, and for changesin pH, changes in density, changes in viscosity, and changes inconductivity. In other embodiments, the computing system 100 may predictthe composition and properties of the drilling fluid exiting the welland compare the predicted properties to the properties of the currentsample of the fluid leaving the well. Act 412 and act 414 may berepeated at regular or irregular intervals and the results may be storedin memory 120. In some embodiments, act 412 and act 414 are repeatedevery hour, every several hours, every day, or as otherwise desired. Inother embodiments, act 412 and act 414 may be repeated at incrementaldrilling depths, such as every 50 feet, every 100 feet, or every 250feet.

In some embodiments, the sensitivity of the monitoring system can beimproved by adding a dye to an analyzed fluid or to a drilling fluid.The dye may become fluorescent when it binds to metal ions. Non-limitingexamples of such dyes include rhodamine B and fluorescein. The dyes maydetect the presence of metal ions, such as Cu²⁺, Pb²⁺, and Fe³⁺. Whenthe dye molecule reacts with a metal ion, such as those produced fromthe corrosion of well materials, the dye may fluoresce under UV light.In some embodiments, act 414 may include monitoring a fluid leaving thewell with a sensor to determine the fluorescence of the fluid leavingthe well. An increase in the fluorescence of the fluid leaving the wellmay be an indication of corrosion within the well.

The samples obtained in act 414 may be analyzed by any suitable methodfor determining a composition, a concentration of one or more elements,ions, compounds, or chemical species, and a suitable method ofdetermining a pH, viscosity, density, redox potential, and/or electricalresistivity. In some embodiments, the composition of the sample, or thepresence and/or concentration of one or more elements, molecules,compounds, or chemical species within the sample, may be determined byatomic absorption spectroscopy (AAS), inductively coupled plasma massspectrometry (ICP-MS), atomic emission spectroscopy (AES), Fouriertransform infrared (FTIR) spectroscopy, fluorescence spectroscopy, gaschromatography, high-performance liquid chromatography (HPLC),volumetric analysis, optical analysis, gravimetric analysis,electrochemical analysis, other methods to determine chemicalcomposition (e.g., the presence of one or more marker materials withinthe sample), physical properties, and combinations thereof. In someembodiments, the solution composition and pH may be monitored at thesurface by obtaining samples at the surface. In other embodiments, thedrilling fluid may be at least partially analyzed below the surface withone or more sensors located within the downhole system.

Corrective action may be taken when one or more marker materialsidentified in act 410 is present in the drilling fluid exiting the wellsampled in act 412. Act 416 includes taking a particular action if oneor more of the identified markers is present in a sample obtained in act412. For example, if the drilling fluid at the surface includes one ormore markers indicative of degradation within the well, the compositionof the drilling fluid into the well may be adjusted to mitigate thereactions. In some embodiments, the processor 110 may send a signal toalter a concentration of a drilling fluid being pumped into the well.For example, the processor 110 may send a signal to a chemical injectionpump to increase a concentration of a corrosion inhibitor, an oxygenscavenger, an H₂S scavenger, or other additive into the well.Non-limiting examples of corrosion inhibitors include chemicals thatform a thin film on a metal surface to passivate the exposed metalsurfaces. In some embodiments, the corrosion inhibitor is a filmingamine. If the concentration of lithium or strontium (or any otherelement present in the formation water) increases, the density of thedrilling fluid may be increased to reduce or eliminate the formationwater from flowing into the well. In other embodiments, fluid losses maybe mitigated by stabilizing the wellbore, such as by fracture sealing,stress caging, or other stabilization techniques. If the concentrationof a metal ion such as chromium, iron, nickel, magnesium, cobalt, lead,copper, manganese, titanium, etc., increases, the drilling fluidcomposition may be adjusted. The concentration of the corrosioninhibitors may be monitored to determine the effectiveness of theinhibitors. In some embodiments, the concentration of a filming amine inthe drilling fluid may be monitored to determine the effectiveness ofthe treatment. In other embodiments, an additive, such asethylenediaminetetraacetic acid (EDTA) is added to the drilling fluid toreduce or eliminate the precipitation of solids (e.g., barium sulfate)within the wellbore or scale inhibitors or scale removers are added ifscaling within the well is expected. The concentration of corrosioninhibitors, scale inhibitors, or scavengers added to the drilling fluidto reduce corrosion, scaling, or degradation may be monitored todetermine the effectiveness of the additives.

Act 418 includes actions that may be taken if the sample obtained in act412 includes marker materials not predicted by the computing system 100in act 406 or act 410. Act 418 includes repeating act 406 and act 410until the computing system 100 predicts the marker material that wasinitially unpredicted by the computing system 100. In some embodiments,the computing system 100 may predict a reaction that may cause thepreviously unpredicted marker material to form. For example, an assumed(e.g., predicted) temperature or pressure of the formation, or anestimated composition of the formation or formation fluids may bealtered until the predicted composition of the formation fluid at thesurface sufficiently matches the composition of a sample at the surfacewithin acceptable tolerances. The computing system 100 may iterativelyalter at least one of the assumed temperature of the formation and acomposition of the formation or formation fluid in an iterative processuntil the predicted composition of the formation fluid at the surfacematches the composition of a sample at the surface within acceptabletolerances. In some embodiments, the temperature and pressure may bepredicted or modeled based on the depth of the formation or formationfluid.

Although FIG. 4 has been described with reference to a drilling process,the method 400 may include monitoring a system during a stimulationand/or production period. For example, fluids pumped into the wellduring drilling and completion may damage the surrounding formation byentering the reservoir rock and blocking pores to the reservoir. In someembodiments, stimulation fluids may dissolve the materials blocking thepores to the reservoir and blocking the flow of formation fluid out ofthe pores and to the surface. After initial completion of the wellbore,it is common to use concentrated acids (e.g., formic acid, acetic acid,hydrochloric acid, hydrofluoric acid, mixtures thereof, etc.) in anacidizing process to dissolve the materials blocking the pores of theformation and surfactants used in a stimulation phase.

Possible reactions between the stimulation fluid, the formation fluid,the drill string, the casing string, and residual drilling fluidremaining in the formation may be predicted by the computing system 100.With continued reference to FIG. 4, act 406 may include predictingreactions that may take place between stimulation fluids and at leastone of the well equipment, cement, the formation, formation fluids, anddrilling fluid remaining in the well. Thus, act 406 may includepredicting the conditions within the well and predicting the reactionsbetween the drilling fluid and the wellbore equipment, reactions betweenthe stimulation fluid and the wellbore equipment, and reactions betweenthe drilling fluid and the stimulation fluid. For example, thestimulation fluid may react with one of the drill string, the casingwithin the well, or other material within the well. Act 408 may includeadjusting the stimulation fluid (e.g., a composition of the stimulationfluid) to reduce or eliminate undesired predicted reactions that maydamage the wellbore equipment. If the computing system 100 predictssubstantially harmful reactions between the stimulation fluid and thewell, the selection of the stimulation fluid and/or the technicalequipment may be adjusted. Act 410 may include determining markermaterials for each of the reactions identified in act 406 (e.g.,degradation reactions, etc.). Act 414 may include monitoring the fluidleaving the well for the marker materials identified in act 410. In someembodiments, the computing system 100 compares a current sample of thefluid leaving the well to historic data in the memory 120. In otherembodiments, the computing system 100 may predict the composition andproperties of the fluid exiting the well and compare the predictedproperties to the properties of the current sample of fluid exiting thewell.

During operation, the fluid produced at the surface may be analyzed asdescribed above to monitor for the marker materials identified in act410. For example, the detection of a metal ion in the stimulation fluidmay be an indication of corrosion caused by a reaction of thestimulation fluid and one of a drill string, metal casing, or otherwellbore equipment. Act 416 includes taking appropriate action if aconcentration of a marker material in the fluid produced at the surfacechanges (e.g., increases or decreases). In some embodiments, theprocessor 110 may send a signal to alter a concentration of astimulation fluid into the well. In other embodiments, the processor 110may send a signal to a chemical injection pump to increase aconcentration of a corrosion inhibitor or other additive into the well.

Referring to FIG. 5, a downhole system 500 includes a productioncomponent 510 in a formation 505. The production component 510 mayinclude a metal casing 520. Cement 530 may seal at least a majority ofthe area of the metal casing 520 from the formation 505. Productioncomponent 510 may include a coating 515 on at least one of the exteriorand interior of the production component 510. For example, coating 515may line the interior of a production string. The coating may includematerials such as an acrylic coating, an elastomeric coating, an epoxycoating, and combinations thereof. Non-limiting examples of coating 515include polyvinyl chloride (PVC), polytetrafluoroethylene (PTFE),fluorinated ethylene propylene (FEP), polyvinylidene fluoride (PVDF),and combinations thereof. Formation fluid may flow from stream 550within the formation 505 to produced fluid 560 at the surface. Thecomposition of the produced fluid 560 may be different than thecomposition of the formation fluid within the formation 505 due to thechanges in temperature and pressure within the formation 505 and thesurface and also due to mixing with drilling fluid, stimulation fluid,or completion fluid remaining in the formation 505. For example, as theformation fluid travels to the surface, a portion of the fluid may degasand/or materials may precipitate out of the formation fluid. In someembodiments, the formation fluid may mix with an injected fluid and withany drilling fluid, stimulation fluid, or completion fluid that remainsin the formation after such processes are complete.

FIG. 6 shows downhole system 500 and the various reactions that may takeplace between the formation fluid and various components of the system500 as the formation fluid travels from the formation 505 to thesurface. Reaction 552 includes a degradation of the coating 515 of theproduction component 510. Reaction 554 includes corrosion of theproduction component 510 (FIG. 5) (e.g., production casing). Reaction556 includes corrosion of casing 520 and reaction 558 includesdegradation of cement 530.

Referring to FIG. 7, an injected fluid 580 including one or morechemicals may be injected into the formation 505 through injection well570. The injected fluid 580 may travel into and distribute in theformation 505 to the production well. The injected fluid 580 may mixwith the formation fluid stream 550 and may react with the formation 505and the formation fluid in the vicinity of the production well. Theinjected fluid 580 may also react with any residual drilling,stimulation, or completion fluid remaining within the formation 505.

Referring to FIG. 8 a method 800 of monitoring a condition within thewell includes predicting corrosion and degradation of the downholesystem 500 (FIG. 5, FIG. 6). The method 800 includes act 802, whichincludes drilling and completing a well. Act 804 includes an optionalact of obtaining and determining a composition of a sample of formationfluid from the well during or soon after drilling of the wellbore. Act806 includes predicting a composition of the formation fluid using theat least one processor 110, such as with the software of the computingsystem 100, similar to act 404 described above. In some embodiments, aninitial prediction of the composition of the formation fluid may notmatch the samples analyzed in act 804. The inputs to the at least oneprocessor 110 may be altered to calibrate the predicted composition ofthe formation fluid to the actual composition obtained and analyzed inact 804.

Act 808 includes producing a sample of the formation fluid at thesurface (e.g., a produced fluid) after completion of the well anddetermining the properties of the produced fluid, such as at least oneof the chemical composition, pH, density, viscosity, and electricalconductivity. The composition of the sample may be determined by similarmethods described above with reference to act 414 of FIG. 4.

Act 810 includes predicting the composition of the sampled fluidobtained in act 808, with the computing system 100, similar to act 406described above. The computing system 100 and the memory 120 may besubstantially similar to that described above with respect to FIG. 4.The memory 120 may also include information about the formation fluid,such as formation fluid composition, density, viscosity, and pH. Thepredicted composition may match the composition of the actual sampleobtained in act 808. In some embodiments, where the initially predictedcomposition of the produced fluid does not match the actual compositionof the produced fluid, inputs to the computing system 100 may bealtered, as described above with reference to act 418 of FIG. 4.

Act 812 includes identifying a reference fluid composition to be used bythe computing system 100 (FIG. 1) to predict degradation within thewell. The reference fluid composition may be that predicted by thecomputing system 100 from an assumed starting formation fluidcomposition, or the reference fluid composition may be that predicted bythe computing system 100 after calibrating the inputs to the computingsystem 100 with a sample of produced fluid at the surface.

Act 814 includes predicting chemical reactions (e.g., reactions 552,554, 556, and 558) (FIG. 6) that may take place within the well.Non-limiting examples of such reactions include the degradation ofcoating 515, corrosion of the production component 510, corrosion of thecasing 520, or degradation of the cement 530 (FIG. 5, FIG. 6). In someembodiments, the computing system 100 may predict reactions that maytake place between the formation fluid and at least one of residualdrilling fluid, stimulation fluid, completion fluid, and injected fluidusing information about the well, thermodynamic equations, reactionkinetics, and equilibrium equations, as described above with referenceto FIG. 4. The computing system 100 may predict how the composition ofthe produced fluid will change due to reactions that may occur betweenthe formation fluid and the wellbore equipment.

Act 816 includes identifying characteristic markers for each of thereactions predicted in act 814. For example, each of the predictedreactions in act 814 may result in one or more unique marker materialsin the produced fluid, such as a change in composition or a change in aproperty (e.g., pH, density, viscosity, electrical conductivity, etc.)of the produced fluid. The computing system 100 (FIG. 1) may identifyone or more unique marker materials for each of the reactions predictedin act 814. The computing system 100 may determine that the one or moremarkers in a produced fluid is an indication of corrosion or damagewithin the well. For example, where the formation water includes lithiumor strontium, the presence of lithium or strontium in a produced fluidsample may be an early indication that the formation water is mixinginto the produced fluid. As another example, degradation of cementlining the wellbore may be detected by a decreased concentration ofmagnesium, or copper, an increase in pH values, or combinations thereof.Iron corrosion may be detected by reduced sulfate concentrations,increased iron concentrations, increased pH, and combinations thereof.Other marker materials may include ions of copper, chromium, titanium,manganese and nickel in the drilling fluid.

Concentrations of key elements may be monitored by routine sampling ofthe produced fluid. Act 818 includes regularly sampling and analyzingthe produced fluid during production. The samples may be obtained andanalyzed at the surface (i.e., outside the wellbore). In otherembodiments, the formation fluid may be analyzed by sensors locatedwithin the wellbore. The samples may be analyzed at least substantiallycontinuously, or at regular or irregular time intervals.

The composition of the produced fluid may change during or aftercorrosion or degradation within the downhole environment. For example,the produced fluid at the surface may be contaminated with one or moremarker materials identified in act 816 during corrosion or degradationof the well casing, lining, or cement. Act 820 includes monitoring thesamples obtained in act 818 for changes in composition and properties,such as for changes in the marker materials. For example, theconcentration of marker materials for each of the corrosion ordegradation processes identified in act 814 may be monitored forchanges. The results of each sample may be recorded and stored in thememory 120 (FIG. 1) to monitor the composition of the produced fluidover time. In some embodiments, the computing system 100 (FIG. 1)compares a current sample of the fluid exiting the well to historic datain the memory 120. In other embodiments, the computing system 100 maypredict the composition and properties of the fluid exiting the well andcompare the predicted composition and properties to the actualcomposition and properties of the fluid leaving the well. Act 820 andact 818 may be repeated at least substantially continuously, or atregular or irregular time intervals to monitor the composition of theproduced fluid.

Act 822 includes taking a particular action if one or more of theidentified markers is present in the sample obtained in act 818. Forexample, if at least one of the identified markers is detected in theproduced fluid, various additives may be added to the system. Thecomputing system 100 (FIG. 1) may suggest taking one or more correctiveactions to reduce corrosion. In some embodiments, the computing system100 may send a signal to a chemical injection pump to increase aconcentration of at least one additive to the well. By way ofnon-limiting example, a decreasing concentration of magnesium or leadand an increase in a pH of the formation fluid may indicate damage tothe cement within the wellbore. Corrective actions may include repairingthe cement of the wellbore, altering the salinity of a floodingsuspension, or adding various additives to the wellbore. If theconcentration of a metal ion such as chromium, iron, nickel, magnesium,cobalt, lead, copper, manganese, titanium, etc., increases, one or morecorrosion inhibitors, scavengers, additives, or biocides may be added tothe wellbore. The fluid exiting the well may be sampled after taking oneor more corrective actions. For example, after increasing aconcentration of an additive into the well, the concentration of theadditive in the fluid exiting the well may be determined. In someembodiments, a concentration of the at least one marker is determined inthe fluid exiting the well after taking one or more corrective actions.

Act 824 includes actions that may be taken if the sample obtained in act818 includes compounds not predicted as marker materials in act 816. Insome embodiments, where additional elements or materials are present inthe samples of act 818, each of act 814 and act 816 may be repeateduntil the computing system 100 (FIG. 1) determines the source of theunpredicted material. For example, act 814 may be repeated until thecomputing system 100 predicts a reaction that explains the presence ofthe unpredicted material. Thus, the computing system 100 maycontinuously predict the composition of the fluid exiting the well asinformation becomes available.

While the disclosure is susceptible to various modifications andalternative forms, specific embodiments have been shown by way ofexample in the drawings and have been described in detail herein.However, the disclosure is not intended to be limited to the particularforms disclosed. Rather, the disclosure is to cover all modifications,equivalents, and alternatives falling within the scope of the disclosureas defined by the following appended claims and their legal equivalents.

What is claimed is:
 1. A method of monitoring degradation of a wellbore,the method comprising: predicting at least one reaction between at leastone of a formation fluid, a drilling fluid, a stimulation fluid, acompletion fluid, an injected fluid, a component of wellbore equipment,a formation, and another of the formation fluid, the drilling fluid, thestimulation fluid, the completion fluid, the injected fluid, thecomponent of wellbore equipment, and the formation using at least one ofthermodynamic equations and chemical reaction kinetics equations;identifying at least one property of a fluid exiting the wellbore,wherein the at least one property is indicative of the at least onereaction; and analyzing the fluid exiting the wellbore for changes inthe at least one property.
 2. The method of claim 1, further comprisingdetermining a composition of at least one of the formation fluid, thedrilling fluid, the stimulation fluid, the completion fluid, theinjected fluid, the component of wellbore equipment, and the formationand predicting the at least one reaction using the composition of the atleast one of the formation fluid, the drilling fluid, the stimulationfluid, the completion fluid, the injected fluid, the component ofwellbore equipment, and the formation.
 3. The method of claim 2, whereindetermining a composition of at least one of the formation and theformation fluid comprises at least one of wellbore logging the formationand sampling the at least one of the formation and the formation fluidto determine a property indicative of a concentration of at least onechemical species within the at least one of the formation and theformation fluid.
 4. The method of claim 1, wherein predicting at leastone reaction using at least one of thermodynamic equations and chemicalreaction kinetics equations comprises predicting the at least onereaction employing at least one of a subsurface temperature and asubsurface pressure.
 5. The method of claim 4, wherein the at least oneof a subsurface temperature and a subsurface pressure is measured with asensor.
 6. The method of claim 4, wherein predicting the at least onereaction employing at least one of a subsurface temperature and asubsurface pressure comprises predicting the at least one reaction withat least one of a predicted temperature and a predicted pressure withinthe wellbore.
 7. The method of claim 1, wherein analyzing the fluidexiting the wellbore for changes in the at least one property comprisesanalyzing the fluid within the wellbore or analyzing a sample of thefluid outside the wellbore.
 8. The method of claim 1, whereinidentifying at least one property of a fluid exiting the wellborecomprises identifying a concentration of one or more ions, elements,compounds, molecules, substances, or materials that are indicative ofthe at least one reaction.
 9. The method of claim 1, wherein analyzingthe fluid exiting the wellbore for changes in the at least one propertycomprises analyzing the fluid exiting the wellbore for changes in aconcentration of at least one of iron, chromium, nickel, magnesium,cobalt, lead, manganese, copper, and titanium.
 10. The method of claim1, wherein analyzing the fluid exiting the wellbore for changes in theat least one property comprises analyzing the fluid exiting the wellborefor changes in at least one of strontium and lithium.
 11. The method ofclaim 1, wherein analyzing the fluid exiting the wellbore for changes inthe at least one property comprises analyzing the fluid for changes in aconcentration of an elastomer.
 12. The method of claim 1, whereinanalyzing the fluid exiting the wellbore for changes in the at least oneproperty comprises analyzing the fluid exiting the wellbore for changesin at least one of a pH, a redox potential, a resistivity, aconductivity, and a salinity of the fluid.
 13. The method of claim 1,further comprising: forming at least a portion of the wellbore equipmentfrom a material comprising a plurality of layers, forming the at least aportion of the wellbore equipment comprising: forming an exposed firstportion comprising a first material; and forming an initially unexposedsecond portion comprising a second material.
 14. The method of claim 13,wherein analyzing the fluid exiting the wellbore for changes in the atleast one property comprises analyzing the fluid exiting the wellborefor changes a concentration of at least one of the first material andthe second material.
 15. The method of claim 13, wherein: forming anexposed portion comprising a first material comprises forming an exposedfirst layer comprising the first material; and forming an initiallyunexposed second portion comprises forming an initially unexposed secondlayer comprising the second material.
 16. The method of claim 1, whereinanalyzing the fluid exiting the wellbore for changes in the at least oneproperty comprises adding a dye to a fluid entering the wellbore andmonitoring the fluorescence of the fluid exiting the wellbore.
 17. Amethod of reducing degradation of a wellbore, the method comprising:determining a composition of at least one of a formation and a formationfluid within a wellbore; predicting at least one reaction between theformation fluid and at least one of wellbore equipment, the formation, adrilling fluid, a stimulation fluid, an injected fluid, and a completionfluid; identifying at least one chemical species in the fluid exitingthe wellbore, wherein the at least one chemical species is indicative ofthe at least one predicted reaction; and adjusting a composition of theinjected fluid into the wellbore responsive to detection of the at leastone chemical species indicative of the at least one predicted reactionin the fluid exiting the wellbore.
 18. The method of claim 17, whereinadjusting a composition of the injected fluid comprises increasing aconcentration of at least one of a corrosion inhibitor, an oxygenscavenger, and an H₂S scavenger in the injected fluid.
 19. The method ofclaim 18, further comprising determining a concentration of the at leastone of the corrosion inhibitor, the oxygen scavenger, and the H₂Sscavenger in a produced fluid exiting the wellbore.
 20. A system fordetecting degradation of wellbore equipment within a wellbore, thesystem comprising: a computing system comprising: a computer memoryconfigured for storing computing instructions; and a processor operablycoupled to the computer memory and configured for retrieving thecomputing instructions from the computing memory and executing thecomputing instructions to predict a composition of a subsurfaceformation fluid and at least one reaction between the subsurfaceformation fluid and at least one of a drilling fluid, a stimulationfluid, a completion fluid, an injected fluid, and at least one componentof wellbore equipment; and a sensor operably coupled to the computingsystem, the sensor located and configured to detect at least oneproperty of a produced fluid, wherein the at least one property isindicative of the at least one reaction.